7Scenarios

This chapter considers the extent to which renewable technologies might contribute to the future U.S. electric power supply. To come to conclusions about the level that renewables might contribute to electricity generation, we focus on scenarios of the technologic, economic, environmental, and implementation-related characteristics that may enable a greater fraction of renewable electricity. How much these factors might affect the market penetration of any individual renewable resource would depend on the rate at which generation from additional renewables is introduced. Under business as usual conditions without major policy initiatives to speed deployment, the introduction of renewables into electricity markets can continue at a moderate pace, with the growth rate and technology learning following a conventional S curve. But if policy makers or external conditions were to bring a sense of urgency to addressing concerns such as energy security or climate change, the question would become how to accelerate the market penetration of renewables while minimizing impacts on electricity’s price, the environment, the reliability of electricity service, and the ability of industry to manufacture and deploy relevant technologies. The scenarios selected by the panel allow exploration of such issues.

The scenarios discussed below in this chapter were chosen to represent aggressive but achievable rates of renewables deployment in the U.S. electricity sector, provided that significant policy and financial resources are devoted to the effort. Scenarios do not represent a simple extrapolation of historical growth rates; instead, they reflect a more integrated perspective on the conditions required to scale up renewables deployment. The panel’s criteria in choosing the particular scenarios it presents were whether the scenario was developed with input from

Citation Manager

Below are the first 10 and last 10 pages of uncorrected machine-read text (when available) of this chapter, followed by the top 30 algorithmically extracted key phrases from the chapter as a whole.Intended to provide our own search engines and external engines with highly rich, chapter-representative searchable text on the opening pages of each chapter.
Because it is UNCORRECTED material, please consider the following text as a useful but insufficient proxy for the authoritative book pages.

Do not use for reproduction, copying, pasting, or reading; exclusively for search engines.

OCR for page 291
7 Scenarios
T
his chapter considers the extent to which renewable technologies might
contribute to the future U.S. electric power supply. To come to conclu-
sions about the level that renewables might contribute to electricity
generation, we focus on scenarios of the technologic, economic, environmental,
and implementation-related characteristics that may enable a greater fraction of
renewable electricity. How much these factors might affect the market penetra-
tion of any individual renewable resource would depend on the rate at which
generation from additional renewables is introduced. Under business as usual
conditions without major policy initiatives to speed deployment, the introduction
of renewables into electricity markets can continue at a moderate pace, with the
growth rate and technology learning following a conventional S curve. But if pol-
icy makers or external conditions were to bring a sense of urgency to addressing
concerns such as energy security or climate change, the question would become
how to accelerate the market penetration of renewables while minimizing impacts
on electricity’s price, the environment, the reliability of electricity service, and the
ability of industry to manufacture and deploy relevant technologies. The scenar-
ios selected by the panel allow exploration of such issues.
The scenarios discussed below in this chapter were chosen to represent
aggressive but achievable rates of renewables deployment in the U.S. electric-
ity sector, provided that significant policy and financial resources are devoted to
the effort. Scenarios do not represent a simple extrapolation of historical growth
rates; instead, they reflect a more integrated perspective on the conditions required
to scale up renewables deployment. The panel’s criteria in choosing the particular
scenarios it presents were whether the scenario was developed with input from

OCR for page 291
Electricity from Renewable Resources
multiple stakeholder groups and whether it underwent peer review. The panel
also considered the degree to which each scenario assessed not simply deployment
rates and cumulative levels of generation but also economic, financial, human,
and environmental facets. Many of the scenarios described here have been released
over the past few years, which helps ensure that inputs to the scenarios reflect
recent conditions.
OBJECTIVES FOR SCENARIOS
Scenarios provide conceptual and quantitative frameworks to describe and assess
how renewable resources’ contribution to electricity supply might be significantly
increased. Such scenarios are a primary way to quantify materials and manu-
facturing requirements, human and financial resource needs, and environmental
impacts that come with greatly expanding electricity generation from renewable
electricity sources. These scenarios typically use qualitative analysis, quantitative
assumptions, and computational models of the energy, economic, and/or electricity
systems. They attempt to integrate the environmental, technologic, economic, and
deployment-related elements into an internally consistent analytical framework.
The panel considered two types of scenarios. The first type analyzes increased
market penetration of a single resource, such as solar or wind. A prominent
example is the 20 percent wind study (DOE, 2008) described in more detail in the
following section. Examples for solar energy include the Solar America Initiative
(DOE, 2007b), the U.S. Photovoltaic Industry Roadmap (SEIA, 2001, 2004), and
the 10 percent solar study (Pernick and Wilder, 2008). The scenarios described
here are used to assess issues such as:
• Land-use impacts, manufacturing and employment requirements, and
economic costs associated with an assumed market penetration of a
single renewable resource (e.g., 20 percent electricity generation from
wind power or more than 50 percent electricity generation from solar);
• The additional transmission, distribution, and other technologies
needed to incorporate or enhance the use of intermittent renewable
resources in the electricity market; and
• The cost-reduction trajectories needed to make solar electricity widely
competitive with other electricity sources.

OCR for page 291
Scenarios
A second type of scenario examines how renewables interact with other
sources of electricity, other sources of energy, and end-use energy demands (CCSP,
2007; EIA, 2008a). Through the use of long-term energy–economic models, these
scenarios enable assessment of the potential impacts of demographic, economic,
and regulatory factors on renewable electricity within a framework that considers
the whole energy sector. The scenarios described here are used to explore issues
such as:
• How wider energy–economic interactions and the electricity market
could affect market penetration by renewables;
• The impacts of environmental, economic, and/or energy policies on
end-use demand and electricity generation from renewables and other
sources.
These scenarios, as with the reference case scenario presented in Chapter 1,
are not predictors of the future, and the results of scenarios are not forecasts.
Rather, they are descriptions of one set of conditions that could result in signifi-
cantly increased market penetration by one or several renewables over what is
estimated based on present-day conditions and a business-as-usual future. They
demonstrate the costs, benefits, and scale of the challenges associated with increas-
ing the integration of renewables into the electricity sector.
ExAMPLES OF HIGH-PENETRATION SCENARIOS
20 Percent National Wind Penetration Scenario
The American Wind Energy Association and DOE’s National Renewable Energy
Laboratory (NREL) developed a scenario assuming that 20 percent of electricity
generation would come from wind power by 2030 (DOE, 2008). The scenario
included assessments of the wind resource base, materials and manufacturing
requirements, environmental and siting issues, transmission and system integra-
tion, costs, and public policy drivers (Smith and Parsons, 2007). The scenario
estimated that more than 300 GW of new wind power capacity would be needed
to meet a goal of 20 percent market penetration by wind, of which about 250 GW
would be installed onshore and 50 GW installed offshore. Under this scenario,
in 2030 wind power would produce about 1.2 million GWh out of a total U.S.

OCR for page 291
Scenarios
extremely large expansion of manufacturing, materials, and installation capacities.
It projected that by 2018 the amount of annual installed capacity in the United
States would be more than 16 GW, compared to a global wind turbine manufac-
turing output of about 15 GW in 2007 (DOE, 2007a). As discussed in Chapter 1
of the present report, an additional 5 GW of capacity was added in the United
States in 2007 and more than 8 GW in 2008, both exceeding the trajectory for the
20 percent wind scenario. Even assuming that growth outside the United States
would be more modest, this scenario would require a continued large expansion
of the manufacturing base. Global growth in wind power is likely to continue to
be strong. For example, the Commission of the European Communities’ roadmap
for renewables proposes that the European Union establish a mandatory target of
20 percent for renewable energy’s share of energy consumption in the EU by 2020,
much of which would be met with wind power (Commission of the European
Communities, 2007).
The 20 percent wind scenario also contains critical challenges to fulfill mate-
rials, capital, and employment requirements. Table 7.1 shows the level of raw
materials needed to meet this scenario. While some quantities would be small
relative to global production, Smith and Parsons (2007) concluded that supplying
fiberglass, core materials (balsa and foam), and resins could be difficult, as would
supplying a sufficient number of wind turbine gearboxes. Assuming that the aver-
age-sized wind turbine would be in the 1–3 MW range, with modest introduc-
tion of large 4- to 6-MW turbines, there could be a total of almost 100,000 wind
turbines installed (Wiley, 2007; DOE, 2008). The average number of turbines
TABLE 7.1 Raw Materials Requirements for 20 Percent Wind Scenario (thousands of tons per
year)
Glass- Carbon
Reinforced Fiber
Year Concrete Steel Aluminum Copper Plastic Composite Adhesive Core
2010 6,800 460 4.6 7.4 30 2.2 5.6 1.8
2015 16,200 1,200 15 10 74 9 15 5
2020 37,000 2,600 30 20 162 20 34 11
2025 35,000 2,500 28 19 156 19 31 10
2030 10
34,000 2,300 26 18 152 18 30
Source: Adapted from material in Wiley, 2007.

OCR for page 291
Electricity from Renewable Resources
TABLE 7.2 Net Present Value Direct Electricity Sector Costs for 20 Percent Wind Scenario and
No-New-Wind Scenario
NPV Direct Costs for 20 Percent NPV Direct Costs for No-New-
Wind Scenario Wind-After-2006 Scenario
(billion U.S. 2006$) (billion U.S. 2006$)
Wind technology O&M costs 51 3
Wind technology capital costs 236 0
Transmission costs 23 2
Fuel costs 813 968
Conventional generation O&M 464 488
Conventional generation capital costs 822 905
Total 2,409 2,366
Note: NPV, net present value; O&M, operation and maintenance.
Source: DOE, 2008.
installed would have to increase from its present level of 2,000 per year to 7,000
per year by 2017 (DOE, 2008).
The NREL Wind Development System (WinDS) model, which simulates gen-
eration capacity expansion in the U.S. electricity sector for wind and other tech-
nologies through 2030, estimates that the 20 percent wind scenario would result
in a direct increased cost for the total electricity sector of $43 billion (U.S. 2006$)
in net present value (NPV) over the no-new-wind case. Table 7.2 shows the break-
down of direct electricity sector costs for the 20 percent wind scenario and the
no-new-wind scenario. Overall, increases in wind power generation costs (capital
and operation and maintenance [O&M] expenses) would be partially offset by
lower capital, O&M, and fuel costs for other electricity sources. The total capital
costs for wind under this scenario would be $236 billion NPV, and O&M cost
would be $51 billion NPV. These cost estimates do not consider the total capital
required for potential investments in manufacturing capacity, expanded employ-
ment training, or other needs, and do not represent the indirect costs to the econ-
omy. According to the scenario, in 2030, 20 percent market penetration by wind
would provide well over 140,000 direct manufacturing, construction, and opera-
tions jobs, as indicated by DOE’s Job and Economic Development (JEDI) model
(Goldberg et al., 2004; Wiley, 2007; DOE, 2008). This projection would include
more than 20,000 jobs in manufacturing, almost 50,000 jobs in construction, and
more than 75,000 jobs in operations (DOE, 2008).

OCR for page 291
Scenarios
Integration of Wind Power into the Electricity System
Under this high-market-penetration scenario, integrating 20 percent wind power
into the electricity system would require investment in the electricity grid and
other parts of the electricity system. Transmission could be the biggest obstacle to
seeing levels of wind power rise to 20 percent. Studies of wind integration at the
utility and state level show that incorporating significant amounts of wind power
into the electricity grid, while feasible, would require improvements in the trans-
mission grid, wind forecasting, and other modifications to the electricity system,
which would impose additional costs (Zavadil et al., 2004; GE Energy, 2005;
DeMeo et al., 2005; UWIG, 2006; Parsons, 2006). The 20 percent wind integra-
tion study included a conceptual framework of the regional transmission system
upgrades needed to move electricity from high-resource to high-demand areas
(Figure 7.2). The study estimated the cost of expanded transmission at $23 billion,
Wind (MW) Used Inside
Wind (MW) on
Balancing Area
Transmission Lines
100– 300
Existing New
300– 500
100– 200
500– 1000
200– 500
1000– 5000
500– 1000
>5000
>1000
FIGURE 7.2 Map indicating potential new transmission corridors for integrating 300 GW
of wind power. R 7.2
Source: DOE, 2008.

OCR for page 291
Electricity from Renewable Resources
though it recognized the barriers to installing new transmission in general. This
estimate is lower than other estimates. Separately, American Electric Power (AEP)
developed a conceptual interstate transmission plan for integrating more than 300
GW from wind power and for reducing existing transmission bottlenecks. AEP
estimates such a system would include 19,000 miles of new high-voltage (765 kV)
transmission lines and require investments on the order of $60 billion (AEP,
2007). The more recent Joint Coordinated System Plan (JCSP), discussed below
in this section, estimated that integrating 20 percent wind into most of the eastern
U.S. electricity system would require 15,000 miles of new extra-high-voltage lines
at a cost of $80 billion (JCSP, 2009). Though these studies have differing assump-
tions resulting in varying estimates, they all indicate the magnitude of investment
in transmission required to integrate large amounts of wind power into the electric
grid.
Environmental and Energy Impacts
The 20 percent wind power scenario would cause significant land-use and atmo-
spheric emissions impacts. The estimated land area needed to realize this scenario
would be 50,000 km2, which includes the land used directly for the turbines and
other land requirements. Only about 2–5 percent of the land use would be for the
turbines themselves, with the rest of the area between turbines that could be avail-
able for agricultural or other uses.
Figure 7.3 shows reductions of carbon dioxide (CO2) emissions with 20
percent wind compared to the reference case. Atmospheric emissions of CO2 and
other pollutants would be significantly reduced. The scenario estimates that wind
power would replace coal- and gas-fired electricity generation and reduce CO2
emissions to 800 million tons per year in 2030. Also shown in Figure 7.3 is the
trajectory required to reduce electricity sector CO2 emissions by 80 percent, which
is the overall target for reductions of greenhouse gas (GHG) emissions neces-
sary to maintain CO2 at or below 450 parts per million. Increasing wind power
generation would also result in reductions of other atmospheric pollutants associ-
ated with fossil-fuel electricity generation, though there would be emissions from
natural-gas-fired power plants needed for backup generation. However, the impact
on NOx and SO2 emissions is less than what would be expected from assuming
that electricity generation from fossil fuels is replaced with a non-carbon-emitting
technology such as wind power. Because emissions of NOx and SO2 are subject to
caps on emissions, reductions of emissions from wind-generated electricity might

OCR for page 291
Scenarios
4500
CO2 Emissions in the Electricity Sector (Million Metric Tons)
4000
3500
3000
2500
2000
1500
No-New-Wind Reference Case
20% Wind Scenario
1000 Path to 80% Below Today’s Levels by 2050
500
0
2006
2010
2014
2018
2022
2026
2030
Year
FIGURE 7.3 Reductions in CO2 emissions resulting from 20 percent wind scenario com-
pared to the no-new-wind reference case. Also shown is the trajectory for reducing CO2
R 7.3
emissions by 80 percent.
Source: DOE, 2008.
be reallocated to other plants. Other air toxics emitted from coal and natural gas
electricity generation are not capped and would be reduced in replacing fossil-fuel
electricity generation with wind power.
The impact on the energy mix would be largest for natural gas, with the
20 percent wind scenario displacing about 50 percent of electric utility natural
gas consumption compared to 18 percent of coal consumption in 2030 (DOE,
2008). The 20 percent wind scenario would also greatly reduce the need for
imported liquefied natural gas. However, maintaining electricity system reliabil-
ity would require additional capacity from natural gas combustion turbines that
could respond to wind fluctuations in some combination with the transmission
upgrades.

OCR for page 291
Electricity from Renewable Resources
00
Joint Coordinated System Plan
Following the national 20 percent wind study, a multi-stakeholder group within
the Eastern Interconnection prepared a report looking at wind integration issues
from a regional perspective. As with the 20 percent wind study, it included multi-
ple stakeholders in a collaborative that held numerous public workshop meetings.
The Joint Coordinated System Plan (JCSP, 2009) looked at two scenarios, one a
reference case with 5 percent market penetration by wind and the second with
20 percent wind. For the 5 percent wind scenario, the study estimated a need for
10,000 miles of new extra-high-voltage (EHV) transmission lines at an estimated
cost of $50 billion. For the 20 percent wind scenario, the projected transmission
requirement was 15,000 miles of new EHV lines at an estimated cost of $80 bil-
lion. In both cases, the additional transmission allowed renewable and baseload
steam energy from the Midwest to be transmitted to a wider area. The study
assumed that increased wind generation would primarily offset baseload steam
production while requiring more production from fast-response, gas-fired combus-
tion turbines. The JCSP study did not envision electricity storage as having a role
in integrating this level of wind power. That report is intended to be part of an
ongoing set of studies that examine the reliability and economic impacts of alter-
native combinations of supply- and demand-side resource technologies, densities
and locations, and transmission infrastructure options. The group also plans to
conduct sensitivity analyses to determine the implications of varying assumptions
such as fuel and technology costs, load projections, plant retirements, and carbon
regulation options and costs (JCSP, 2009).
Summary of High Wind Power Penetration Scenarios
It is clear that the high wind penetration scenarios outlined above represent a
departure from present conditions. For manufacturers to make the investments
needed to develop such capacities and supply chains, substantial capital and a
stable policy environment would be required. These scenarios also would require
significant land area for the spacing needed between wind turbines, though the
actual area occupied by the turbines is a small portion of the land. Realizing
the scenarios would entail substantial economic activity, including the addition
of thousands of new manufacturing and construction jobs in the wind industry,
and would provide significant carbon reductions. DOE’s 20 percent wind study
estimated a reduced demand for natural gas for electricity generation, though
20 percent wind would increase the need for the use of high-cost combustion-

OCR for page 291
Scenarios 0
turbine natural gas capacity. The 20 percent wind scenarios of both the DOE and
the JCSP demonstrate the need for substantial increases in transmission capacity.
There are sufficient resources, technologies, and generally positive economics to
increase wind power’s contribution to the electricity sector. What these 20 percent
wind penetration scenarios emphasize are the scale of the challenges and the ben-
efits for the future.
High Solar Electricity Penetration Scenarios
A variety of scenarios discuss increased market penetration by solar photovoltaics
(PV) and concentrating solar power (CSP). Examples range from the compara-
tively modest Solar America Initiative (SAI; DOE, 2007b) to the more optimistic
U.S. Photovoltaic Industry Roadmap (PV Roadmap; SEIA, 2001, 2004) and the
“Solar Grand Plan” (Zweibel et al., 2008). Another study examined a scenario for
reaching 10 percent electricity generation from solar by 2025 (Pernick and Wilder,
2008). These scenarios consider issues similar to those addressed in the 20 percent
wind power scenarios, such as the potential impacts of renewables’ high market
penetration on manufacturing, implementation, economics, and the environment.
Further, solar electricity can provide insights into attributes of distributed energy
sources. Because of the higher costs associated with solar energy, all scenarios con-
sider the significant cost reductions that would have to occur to make solar elec-
tricity competitive with other electricity sources.
Distributed Solar PowerSAI and PV Roadmap Scenarios
The SAI and the PV Roadmap scenarios assume that 100–200 GWp (Wp indicates
peak power) of solar PV would be introduced by 2030 and that a majority of
the newly installed generation would be distributed in residential, commercial,
and industrial applications.1 Tables 7.3 and 7.4 provide the assumptions used in
these scenarios. As shown in Table 7.3, the SAI considered two scenarios: a low-
penetration scenario assuming that a total of 5 GWp of PV would be installed
by 2015 and 70 GW by 2030, and a high-penetration scenario assuming that a
total of 10 GWp of PV would be installed by 2015 and 100 GWp by 2030. In the
PV Roadmap scenario, installed capacity would reach 200 GWp by 2030, and
670 GWp by 2050. In order for solar PV to be competitive with other electric-
1TheSAI scenarios assume that all PV installations are distributed electricity sources, and the
PV Roadmap assumes that 1/6 of installed capacity is grid (wholesale) generation.

OCR for page 291
Electricity from Renewable Resources
technologies, such as nuclear, fossil fuel with carbon capture and storage (CCS),
and renewables, would be developed and deployed in the timeframe for emissions
reduction set by the CSA without facing any major problems. The EIA’s high-cost
scenario used the basic assumptions of the core case, except that it applied a 50
percent higher cost of nuclear, fossil fuel with CCS, and biomass-generating tech-
nologies to reflect a more pessimistic perspective regarding the costs of these tech-
nologies and the feasibility of introducing them rapidly on a large scale.
The EIA used the National Energy Modeling System (NEMS) for its analy-
sis of the CSA (EIA, 2003). NEMS calculated changes in energy-related CO2
emissions for the various cases by adjusting the cost of fossil fuels and the GHG
allowance pricesvariables that affect energy demand, the energy mix, and energy-
related CO2 emissions. The NEMS Macroeconomic Activity Module is used for
analyzing the macroeconomic impacts of GHG reduction policies. This module
solves for the energy–economy equilibrium by iteratively interrelating the energy
supply, demand, and conversion modules of NEMS (EIA, 2003). Thus, NEMS
is sensitive to energy prices, energy consumption, and allowance revenues, and
it solves for the effects of policy such as that legislated in the CSA on macroeco-
nomic and industry-level variables.
Energy Market and Electricity Mix
As expected, the projected greenhouse gas emissions in scenarios with emissions
regulations are significantly lower than those in the reference case. The EIA’s core
CSA scenario described above would result in an 85–90 percent reduction of CO2-
equivalent emissions by 2030, and its high-cost case in a 50–60 percent reduction
during the same timeframe. The majority of the emissions reduction would come
from the electric power sector, a projection that is relevant to this panel’s work.
These reductions would be achieved by deployment of new nuclear, renewable,
and fossil fuel with CCS facilities. Major determinants of the energy and economic
impact of the CSA bill include the potential for and the timing of the development
and commercial marketing of low-emissions electricity generation technologies.
Another determinant is the degree to which companies might be able to purchase
emission reduction credits overseas, a topic that is not discussed further here.
Figure 7.7 shows the impact of EIA’s core and high-cost CSA scenarios on
the overall electricity mix. With the regulation of greenhouse gas emissions in
place, coal consumption, especially for electricity generation, would be signifi-
cantly reduced by 2030. Many coal power plants without CCS would be forced

OCR for page 291
Scenarios
6000
Coal Natural Gas Nuclear Renewable Sources
Electricity Generation (Billon Kilowatt-hours)
5000
4000
3000
2000
1000
0
2006 Reference Core High Cost Reference Core High Cost
2020 2020 2020 2030 2030 2030
FIGURE 7.7 Mix of electricity generation from EIA core and high-cost analysis of CSA bill
R 7.7
compared to electricity mix in 2006 and to the AEO 2008 reference.
Source: EIA, 2008b.
to retire early, because retrofitting with CCS technology is generally impracticable,
and so is not simulated in the model. The energy-generation mix for the EIA’s core
CSA scenario would be composed of coal with CCS, nuclear, and renewable tech-
nologies, primarily wind and biomass. One important characteristic of the core
case is the strong growth in nuclear power. If these low-emission technologies face
trouble in deployment, as in the high-cost case, there would be a shift to electricity
generation from natural gas to offset the reduction in coal generation.
The EIA estimated that renewable electricity generation would be signifi-
cantly higher under the provisions of the CSA, with the vast majority of the
increase from wind generation, followed by generation from biomass (EIA,
2008a). How each renewable energy resource would contribute to the total supply
of electricity generated in the three scenarios (AEO 2008, core, and high cost) is
shown in Table 7.8. The increase in total renewable generation is especially strong
in the high-cost case. Table 7.9 shows the projected average annual growth rates

OCR for page 291
Scenarios
growth in the use of biomass for electricity generation: by 2030 biomass it would
be used to generate 4–5 percent of the U.S. electricity supply.
Summary of Macroeconomic Impacts and Model Uncertainties
EIA’s estimates of the macroeconomic impacts of the CSA include an increase in
energy prices for consumers, especially in the cost of electricity, with increases of
11–64 percent, mainly as a result of high GHG allowance prices. Also projected
by EIA is a reduction of total electricity consumption (5–11 percent). The large
increases in energy costs would reduce economic output, lessen purchasing power,
and lower aggregate demand for goods and services. In the core CSA case, the
gross domestic product would fall by approximately 0.2 percent and would fall by
approximately 0.8 percent in the high-cost case.
Many major uncertainties are associated with the EIA projections. It is dif-
ficult to foresee how existing technologies might evolve or what new technologies
might emerge as market conditions change, particularly when those changes are
fairly dramatic. To meet greenhouse gas emission reduction targets, future electric-
ity providers will have to rely on technologies that today play a relatively small
role or have not been built in the United States in some time. The actual cost of
implementing legislation such as the CSA would depend on unknowns such as
future reductions in the cost of renewable technologies, the potential for successful
commercialization of CCS, and future costs for nuclear power—all of which can-
not be predicted by the model.
FINDINGS
Shown in bold below are the most critical elements of the panel’s findings, based
on its examination of previously produced scenarios, regarding the future expan-
sion of renewable electricity and factors affecting renewables expansion and inte-
gration into the U.S. electricity supply system.
Scale of Deployment
An understanding of the scale of deployment necessary for renewable resources
to make a material contribution to U.S. electricity generation is critical to assess-
ing the potential for renewable electricity generation. Large increases over current
levels of manufacturing, employment, investment, and installation will be required

OCR for page 291
Electricity from Renewable Resources
0
for non-hydropower renewable resources to move from single-digit- to double-
digit-percentage contributions to U.S. electricity generation.
The scenarios described in this chapter indicate some of the characteris-
tics and impacts associated with accelerating the integration of more renewable
generation in the U.S. electricity market. Wind power, an intermittent source of
electricity, would be the largest contributor in the near term. DOE (2008) shows
that 20 percent of U.S. electricity generation could be obtained from wind and
integrated into the nation’s electricity system. Follow-up studies such as JCSP
(2009) assess the impacts of 20 percent wind at a regional level. Solar PV and CSP
could also contribute to attaining additional renewable electricity generation by
2035. Solar electricity is the only renewable resource that has a sufficiently large
resource base to supply a majority of the electricity demands of the United States.
Today’s prices prevent solar electricity from being a widespread economic option
at this time. However, the ability of solar PV to produce electricity at the point of
consumption means that it competes with the higher retail price of electricity as
opposed to the wholesale price of electricity. Solar CSP can provide utility-scale
solar power at lower costs than solar PV, though it is limited to favored sites in
the U.S. Southwest that have abundant direct solar radiation. Additional contribu-
tions could come from biopower and conventional geothermal resources, which
can provide baseload power. Thus, if renewables were to contribute an additional
20 percent or more of all U.S. electricity generation by 2035, the largest portion
of new renewable electricity generation would come from wind power, but other
renewables would also contribute to making this goal a reasonable possibility.
The numbers from the 20 percent wind penetration study (DOE, 2008)
demonstrate the challenges and opportunities. To reach the 20 percent target
would require installing 100,000 wind turbines; incurring $100 billion worth of
additional capital investments and transmission upgrades; and requiring 140,000
jobs be filled. Achieving this goal could reduce CO2 emissions by 800 million
metric tons. The high solar market penetration scenarios also present challenges
associated with scaling up this resource. The 10 percent solar study (Pernick and
Wilder, 2008) would require that annual installation of PV increase to almost 50
GW in 2025 and installation of CSP to almost 7 GW, with prices for installed PV
declining to $1.48–1.82/W and prices for installed CSP declining to $0.88/W in
the same timeframe. The cost estimates for reaching the 10 percent solar goal are
$26–33 billion per year, with a total cost of $450–560 billion.
In the panel’s opinion, increasing manufacturing and installation capac-
ity, employment, and financing to levels required to meet the goals for greatly

OCR for page 291
Scenarios
increased solar or wind penetration goals is doable. However, to do so would
require aggressive growth rates, a large increase in manufacturing and installation
capacity, and a large infusion of capital. The magnitude of the challenges is clear
from the scale of such efforts.
Integration of Renewable Electricity
The cost of new transmission and upgrades to the distribution system will be
important factors when integrating increasing amounts of renewable electric-
ity. The nation’s electricity grid needs major improvements regardless of whether
renewable electricity generation is increased. Such improvements would increase
the reliability of the electricity transmission system and would reduce the losses
incurred with all electricity sources. However, because a substantial fraction of
new renewable electricity generation capacity would come from intermittent z dis-
tant sources, increases in transmission capacity and other grid improvements are
critical for significant penetration of renewable electricity sources. According to
the Department of Energy’s study postulating 20 percent wind penetration, trans-
mission could be the greatest obstacle to reaching the 20 percent wind generation
level. Transmission improvements can bring new renewable resources into the
electricity system, provide geographical diversity in the generation base, and allow
improved access to regional wholesale electricity markets. These benefits can also
generally contribute positively to the reliability, stability, and security of the grid.
Improvements in the system’s distribution of electricity are needed to maximize the
benefits of two-way electricity flow and to implement time-of-day pricing. Such
improvements would more efficiently integrate distributed renewable electricity
sources, such as solar photovoltaics sited at residential and commercial units. A
significant increase in renewable sources of power in the electricity system would
also require fast-responding backup generation and/or storage capacity, such as
that provided by natural gas combustion turbines, hydropower, or storage tech-
nologies. Higher levels of penetration of intermittent renewables (above about 20
percent) would require batteries, compressed air energy storage, or other methods
of storing energy such as conversion of excess generated electricity to chemical
fuels. Improved meteorological forecasting could also facilitate increased integra-
tion of solar and wind power. Hence, though improvements in the grid and related
technologies are necessary and valuable for other objectives, significant integration
of renewable electricity will not occur without increases in transmission capacity
as well as other grid management improvements.

OCR for page 291
Electricity from Renewable Resources
Timeframes for Renewable Technologies
For the time period from the present to 2020, there are no current technological
constraints for wind, solar photovoltaics and concentrating solar power, con-
ventional geothermal, and biomass technologies to accelerate deployment. The
primary current barriers are the cost-competitiveness of the existing technologies
relative to most other sources of electricity (with no costs assigned to carbon emis-
sions or other currently unpriced externalities), the lack of sufficient transmission
capacity to move electricity generated from renewable resources to distant demand
centers, and the lack of sustained policies. Expanded research and development
is needed to realize continued improvements and further cost reductions for
these technologies. Along with favorable policies, such improvements can greatly
enhance renewable electricity’s competitiveness and its level of deployment. Action
now will set the stage for greater, more cost-effective penetration of renewable
electricity in later time periods. It is reasonable to envision that, collectively, non-
hydropower renewable electricity could begin to provide a material contribution
(i.e., reaching a level of 10 percent level or more with trends toward continued
growth) to the nation’s electricity generation in the period up to 2020 with such
accelerated deployment. Combined with hydropower, total renewable electricity
could approach a contribution of 20 percent of U.S. electricity by the year 2020.
In the period from 2020 to 2035, it is reasonable to envision that contin-
ued and even further accelerated deployment could potentially result in non-
hydroelectric renewables providing, collectively, 20 percent or more of domestic
electricity generation by 2035. In the third timeframe, beyond 2035, continued
development of renewable electricity technologies could potentially provide lower
costs and result in further increases in the percentage of renewable electricity
generated from renewable resources. However, achieving a predominant (i.e.,
>50 percent) level of renewable electricity penetration will require new scientific
advances (e.g., in solar photovoltaics, other renewable electricity technologies, and
storage technologies) and dramatic changes in how we generate, transmit, and
use electricity. Scientific advances are anticipated to improve the cost, scalability,
and performance of all renewable energy generation technologies. Moreover, some
combination of intelligent, two-way electric grids; scalable and cost-effective meth-
ods for large-scale and distributed storage (either direct electricity energy storage
or generation of chemical fuels); widespread implementation of rapidly dispatch-
able fossil-based electricity technologies; and greatly improved technologies for
cost-effective long-distance electricity transmission will be required. Significant,